The methane-based natural gas is either a by-product of oil fields, being produced in small or medium quantities, in general in association with crude oil, or else it is a major product from a gas field, where it is to be found in combination with other gases, mainly C-2 to C-4 alkanes, CO2, and nitrogen.
When the natural gas is associated in small quantities with crude oil, it is generally treated and separated and then used on site as fuel for turbines or piston engines in order to produce electricity and heat for use in the separation or production processes.
When the quantities of natural gas are large, or indeed substantial, they need to be transported so that they can be used in regions far away, in general on other continents, and in order to do this the preferred method is to transport the gas while it is in the cryogenic liquid state (−165° C.) and substantially at ambient atmospheric pressure. Specialized transport ships known as “methane tankers” possess tanks of very large dimensions with extreme insulation in order to limit evaporation while traveling.
Gas is generally liquefied for transport purposes in the proximity of the production site, generally on land, and that requires substantial installations in order to achieve capacities of several millions of (metric) tonnes per year, with the largest existing units combining three or four liquefaction units, each having a unit capacity of 3 megatonnes (Mt) to 4 Mt per year.
The liquefaction process requires substantial quantities of mechanical energy, with the mechanical energy generally being produced on site by taking a portion of the gas in order to produce the energy needed by the liquefaction process. A portion of the gas is then used as fuel in gas turbines, steam turbines, or piston engines.
Numerous thermodynamic cycles have been developed for the purpose of optimizing overall energy efficiency. There are two main types of cycle. A first type is based on compressing and expanding a refrigerant fluid with a change of phase, while a second type is based on compressing and expanding a refrigerant gas without a change of phase. The terms “refrigerant fluid” and “refrigerant gas” are used to designate a gas or gas mixture circulating in a closed circuit and being subjected to stages of compression, possibly of liquefaction, then of heat exchange with the external medium, and subsequently stages of expansion, possibly of evaporation, and finally of heat exchange with the natural gas for liquefying, which gas comprises methane, and cools little by little to reach its liquefaction temperature at atmospheric pressure, i.e. about −165° C. for LNG.
Said first cycle type with a change of phase is generally used in installations on land and it requires a large amount of equipment and occupies a large footprint. In addition, the refrigerant fluids, generally in the form of mixtures, are constituted by butane, propane, ethane, and methane, which gases are dangerous since in the event of a leak they run the risk of leading to substantial fires or explosions. In contrast, in spite of the complexity of the equipment required, they remain more efficient and they require about 0.3 kilowatt hours (kWh) of energy per kilogram (kg) of LNG that is produced.
Numerous variants of that first type of process with a change of phase in the refrigerant fluid have been developed, and suppliers of technology or of equipment have their own formulations of mixtures associated with their specific equipment, both for so-called “cascade” processes and for so-called “mixed cycle” processes. The complexity of those installations comes from the fact that in those stages where the refrigerant fluid is in the liquid state, and more particularly in separators and in connection pipes, it is appropriate to install gravity collectors in order to bring the liquid phase together and direct it to the cores of heat exchangers where it vaporizes on coming into contact with the methane for cooling and liquefying in order to obtain LNG. Those devices are very bulky, but that does not lead to problems for installations on land, since it is generally simple to obtain an area of land that is large enough to house all of those bulky pieces of equipment side by side. Thus, for installations on land, all of the compressor, heat exchanger, and collector pieces of equipment are generally installed side by side on substantial areas, lying in the range 25,000 square meters (m2) to 50,000 m2, or even more.
The second type of liquefaction process, without any change of phase in the refrigerant gas, is an inverse Brayton cycle or a Claude cycle using a gas such as nitrogen. The efficiency of the second type of process is lower, since it generally requires about 0.5 kWh of energy per kg of LNG produced, i.e.; about 20.84 kilowatt-days per tonne (kW×d/t), but in contrast it presents a substantial advantage in terms of safety since the cycle refrigerant gas, nitrogen, is inert and thus incombustible, which is very advantageous when the installations are concentrated in a small amount of space, e.g. on the deck of a floating support located in the open sea, where said equipment is often installed on a plurality of levels one above another on an area that is reduced to the strict minimum. Thus, in the event of the refrigerant gas leaking, there is no danger of explosion and it then suffices to reinject into the circuit the fraction of the refrigerant gas that has been lost.
Furthermore, that process for liquefying natural gas without a change of phase is very advantageous on board floating supports since the equipment is of much simpler design, because there is no liquid phase in the refrigerant gas. In such installations, all of the equipment is moving practically continuously as a result of the movements of the floating support (roll, pitching, yaw, lurch, surge, heave). Managing a process with a phase change involving a liquid phase of the refrigerant fluid would then be extremely difficult, even for small movements of the floating support, and indeed practically impossible for extreme movements, whereas stationary installations on land do not face the problem of movements.
In spite of the lower energy efficiency of the liquefaction process without a change of phase of the refrigerant gas, this process remains very advantageous since the equipment used, mainly compressors, expanders, turbines, and heat exchangers is much simpler than the equipment required for a liquefaction process involving cycles with a change of phase in a refrigerant fluid, both in terms of the technology used for said equipment and in terms of maintaining the equipment in an environment that is confined, i.e. on board a floating support that is anchored at sea. Furthermore, the running of such installations in operation remains simpler, since this type of cycle is relatively insensitive to variations in the composition of the gas for liquefying, i.e. a natural gas that is constituted by a mixture in which methane predominates. In the cycle with a change of phase in the refrigerant fluid, in order to ensure that efficiency remains good, the refrigerant fluid needs to be matched to the nature and the composition of the gas that is to be liquefied, and the composition of the refrigerant fluid might possibly need to be modified over time as a function of the composition of the natural gas mixture for liquefying as produced by the oil field.
In principle, implementing a cycle of the liquefaction process without a change of phase in the refrigerant gas, such as nitrogen, comprises the four following main elements:                a compressor that increases the pressure of the refrigerant gas and causes it to go from ambient temperature at low pressure to high temperature at high pressure;        a heat exchanger that cools the refrigerant gas from the high temperature at high pressure substantially down to ambient temperature at high pressure;        an expander device, generally a decompression turbine, in which the refrigerant gas expands: its pressure drops and its temperature is then very low; while simultaneously mechanical energy is recovered from the expansion turbine, which mechanical energy is generally reinjected directly to the compressor that is coupled thereto; and        a cryogenic heat exchanger through which there flow both the refrigerant gas at cryogenic temperature and also the gas for liquefying, said refrigerant gas absorbing heat from the gas for liquefying, and thus heating up, while said gas for liquefying gives off heat and cools until it reaches the looked-for liquid state. At the end of the heat exchanger cycle, the refrigerant gas is substantially at ambient temperature and it is then reintroduced into the compressor in order to perform a new closed-circuit cycle.        
Throughout the duration of the cycle, the refrigerant gas remains in the gaseous state and it circulates in continuous manner, as explained above: it releases its “frigories” little by little, i.e. absorbs calories little by little from the gas that is to be liquefied, i.e. a mixture that is constituted for the most part by methane together with traces of other gases.
The gas for liquefying flows as a countercurrent relative to the refrigerant gas, i.e. said natural gas comprising methane enters the heat exchanger substantially at ambient temperature close to the refrigerant gas outlet where the refrigerant gas is substantially at ambient temperature. Thereafter, the natural gas comprising methane advances into the heat exchanger towards colder zones and transfers its heat to the refrigerant fluid: the natural gas comprising methane cools while the refrigerant gas heats up. As the natural gas comprising methane advances into the heat exchanger, its temperature drops, and at the end of its travel it liquefies and its temperature continues to drop until it reaches a temperature T3=−165° C. for a gas containing 85% methane.
Throughout its passage through the heat exchanger(s), the natural gas is liquefied at a pressure P0 lying in the range 5 bars to 50 bars, in general in the range 10 bars to 20 bars, in four main stages:                stage 1: cooling the natural gas from ambient temperature T0 down to T1=−50° C. approximately (this temperature depends on the composition of the natural gas);        stage 2: liquefaction of the natural gas (passing from the gaseous state to the liquid state). Since the natural gas is a mixture of gases at a pressure P0 of a few tens of bars, approximately, this change of state is spread over the temperature range T1=−50° C. to T2=−120° C., approximately;        stage 3: once the natural gas has liquefied completely (LNG), it is at about T2=−120° C., and still at a pressure P0 of several tens of bars approximately. Within the heat exchanger(s), the LNG continues to be cooled until it reaches the temperature T3 of −165° C., which temperature corresponds to LNG being in a liquid phase at atmospheric pressure; and        stage 4: the resulting liquid or LNG is then depressurized down to atmospheric pressure where it remains in the liquid state because its temperature T3 is lower than or equal to −165° C., and it can be transferred to an insulated storage tank, or possibly loaded directly on board a transport ship such as a methane tanker.        
Stage 2 consumes the most energy, since it is necessary to supply the gas with all of the energy that corresponds to its latent heat of vaporization. Stage 1 consumes a little less energy, and stage 3 consumes least energy, but it takes place at the lowest temperatures, i.e. at temperatures around −165° C.
The values given above for T1, T2, and T3 are appropriate for a natural gas comprising 85% methane and 15% of said other components comprising nitrogen and C-2 to C-4 alkanes, and those temperatures may be significantly different for a gas having a different composition.
FIG. 1 is a diagram of an installation for performing a standard process for liquefying natural gas using a refrigerant gas constituted by nitrogen without a change of phase in the refrigerant gas, as described above, with the process being described in greater detail below.
US 2011/0113825 and WO 2005/071333 describe a process for liquefying natural gas in which said natural gas for liquefying is liquefied by causing the natural gas to flow through three cryogenic heat exchangers, while causing three streams of refrigerant gas that remains in the compressed gaseous state without a change of phase to circulate in three closed circuits. Said natural gas for liquefying is liquefied by performing the following concurrent steps:
a) causing said natural gas for liquefying to flow at a pressure P0 that is higher than or equal to atmospheric pressure through the three cryogenic heat exchangers connected in series, namely:                a first heat exchanger (101/5) into which said natural gas enters at a temperature T0, is cooled, and leaves at a temperature T1 lower than T0; then        a second heat exchanger (102/6) in which the natural gas is completely liquefied and leaves at a temperature T2 lower than T1 and higher than T3, where T3 is lower than the liquefaction temperature of the LNG; and        a third heat exchanger (103/7) in which the liquefied natural gas is cooled from T2 to T3; and        
b) causing two streams of the refrigerant gas in the gaseous state at different pressures P1 and P2, referred to respectively as first and third streams, to circulate through two of said heat exchangers in indirect contact with and as a countercurrent relative to the natural gas steam, comprising:                a first refrigerant gas stream at a pressure P1 lower than P3 passing through the three heat exchangers by entering into said third heat exchanger at a temperature T3′ lower than T3, then entering said second heat exchanger at a temperature T2′ lower than T2, and then entering said first heat exchanger at T1′ lower than T1 and leaving said first heat exchanger at a temperature T0′ lower than or equal to T0, said first refrigerant gas stream at P1 and T3′ being obtained by using a first expander (112/9) to expand a first portion (122/16B) of a second refrigerant gas stream (22/15) compressed to the pressure P3 higher than P2, said first portion of the second stream flowing in indirect contact with and as a countercurrent relative to the natural gas, entering said first heat exchanger at T0 and leaving said second heat exchanger substantially at T2; and        a third stream at a pressure P2 higher than P1 and lower than P3 flowing in indirect contact with and as a countercurrent relative to said first stream, passing solely through said second and first heat exchangers, by entering said second heat exchanger substantially at a temperature T2′ and leaving said first heat exchanger at T0′, said third refrigerant gas stream at P2 and T2 being obtained by using a second expander (111/8) to expand a second portion (121/17) of said second refrigerant gas stream (22/15) leaving said first heat exchanger substantially at T1; and        
c) said second refrigerant gas stream compressed at the pressure P3 being obtained by compression in three or four compressors and by cooling said first and second refrigerant gas streams leaving said first heat exchanger respectively at P1 and at P2.
In US 2011/0113825, first and second compressors 113 and 114 are connected in series to compress the refrigerant gas of the first and second streams to P′3, and two other compressors 115a and 115b connected in parallel compress it from P′3 to P3.
In WO 2005/071333, two series-connected compressors 2 and 3 compress said first stream 16d to P′3, and then a third compressor 4 connected in series with the first two compressors compresses said first and third streams to P3.
In the report on the “24th International Conference and Exhibition for the LNG” of May 25, 2009, by Olve Skjeggedal et al. published in the GASTECH 2009 journal, a process of the above-described type having three closed-circuit refrigerant gas streams is described in which said first and second streams are compressed to P′3 by two compressors connected in series, and two other compressors connected in series compress said first and third streams to P3 in order to deliver said second stream.
The process described above is advantageous compared with that of FIG. 1 in that, firstly, instead of a portion D2 of the second stream leaving the first heat exchanger by being expanded and recycled in order to join the first stream at the inlet to the second heat exchanger, this portion D2 of the second stream is recycled to the inlet of the second heat exchanger at an intermediate pressure P2 higher than P1 in a third stream S3 independent of and parallel with S1, i.e. as a cocurrent relative to S1. And because the major portion of the energy is consumed by stage 2 of the process within said second heat exchanger, this makes it possible to increase the transfer to heat and the energy efficiency of the process.
Nevertheless, in the embodiment of US 2011/0113825, all of the external power delivered to said series-connected first and second compressors 113 and 114 relates to the refrigerant gas streams circulating at low and medium pressures P1 and P2, with the energy recovered from the turbines 111 and 112 being reinjected to the two parallel-connected compressors 115a and 115b for compressing the refrigerant gas to high pressure P′3/P3, with no other additional external power being delivered to said parallel-connected compressors 115a and 115b. The two parallel-connected compressors 115a and 115b are powered solely by respective ones of the two energy recovery turbines 111 and 112.
The pressure levels P1 and P2 of the gas leaving the turbines 112 and 111 are different and thus the flow rates of the streams passing through the expanders 111 and 112 are different, and in practice they lie in particular in the range 10% to 20% of the total flow rate for the flow rate of the stream coming from the expander 112, as compared with 80% to 90% for the flow rate of the stream coming from the expander 111. As a result, the compressor 115b recovers only 10% to 20% of the total recovered power compared with the 80% to 90% of the power that is recovered in the compressor 115a. This mismatch in the powers delivered to the two parallel-connected compressors 115a and 115b leads to a major difficulty in stabilizing the operation of the circuit. Running two compressors in parallel can lead to surge phenomena, i.e. one of the compressors prevails over the others by disturbing their inlet and outlet pressures: there is then a risk of one or more of the smaller-capacity compressors operating in “turbine mode”. It is essential to avoid this mode of operation since some or all of the fluid then loops between the compressors, one operating in compressor mode and the other(s) in “turbine mode”: the compression process is then greatly disturbed or even interrupted, and the overall efficiency of the installation then collapses.
The operation of the circuit can be stabilized in conventional manner by means of regulation valves upstream and/or downstream from said parallel-connected compressors 115a and 115b, and/or upstream and/or downstream from said turbines 111 and 112 in order to control the flow rates and the operation of the compressors. Nevertheless, those regulation valves lead to head losses, and thus to losses of energy, thereby greatly affecting the expected overall efficiency and/or the production capacity of the installation.
In WO 2005/071333 and in the report in the above-mentioned GASTECH 2009 journal, all of the compressors are mechanically coupled to a common power source, with all of the power being delivered in undifferentiated manner among the various compressors.